Tool and method for determining formation parameter

ABSTRACT

An apparatus and method of measuring a parameter characteristic of a rock formation in an oil well is provided with a device for generating a sensing field within a volume of the rock formation and a device for causing a flow through the volume in the presence of the sensing field, further including sensors responsive to changes in the volume, wherein a sensor response is indicative of the amounts of fluid, particularly hydrocarbon and water saturations and irreducible hydrocarbon and water saturations. Measurements can be made before the flow affects the measuring volume and after onset of the flow through the measuring volume.

FIELD OF THE INVENTION

The invention relates to apparatus and methods for determiningparameters representative of formation properties and formation fluidproperties of subterranean reservoirs, particularly hydrocarbonreservoirs. More specifically, the invention relates to apparatus andmethods for measuring formation parameters at the location of an inducedflow in the formation.

BACKGROUND

In the course of assessing and producing hydrocarbon bearing formationand reservoirs, it is important to acquire knowledge of formation andformation fluid properties which influence the productivity and yieldfrom the drilled formation. Typically such knowledge is acquired bymethods generally referred to as “logging”.

Logging operations involve the measurement of a formation parameter orformation fluid parameter as function of location, or more specificallydepth in a wellbore. Formation logging has evolved to include manydifferent types of measurements including measurements based onacoustic, electromagnetic or resistivity, and nuclear interactions, suchas nuclear magnetic resonance (NMR) or neutron capture.

NMR measurements are commonly used in the wellbore to probe the NMRdecay behavior of the stationary fluid in the reservoir rock. Duringthese measurements, magnetic fields are established in the formationusing suitably arranged magnets. The magnetic fields induce nuclearmagnetization, which is flipped or otherwise manipulated withon-resonance radio frequency (RF) pulses. NMR echoes are observed, andtheir dependence on pulse parameters and on time is used to extractinformation about the formation and the fluids in it.

In particular, NMR has been used in the oilfield industry to obtaininformation and parameters representative of bound fluids, free fluids,permeability, oil viscosity, gas-to-oil ratio, oil saturation and watersaturations. All these parameters can be derived from measurements ofspin-spin relaxation time, often referred to as T2, spin-latticerelaxation time (T1), and self-diffusion coefficient (D) of themolecules containing hydrogen contained in formation fluids.

On the other hand, fluids are routinely sampled in the well bore withthe help of so-called formation testers or formation fluid samplingdevices. An example of this class of tools is Schlumberger's MDT™, amodular dynamic fluid testing tool. Such a tool may include at least onefluid sample bottle, a pump to extract the fluid from the formation orinject fluid into the formation, and a contact pad with a conduit toengage the wall of the borehole. When the device is positioned at aregion of interest, the pad is pressed against the borehole wall, makinga tight seal and the pumping operation begins.

With the pumping a flow in the formation is induced by extracting fluidfrom the formation through the conduit. The fluid flowing through thetool is analyzed in situ using electrical, optical or NMR based methods.Typically when the fluid is assumed to be ‘pure’ reservoir fluid, i.e.,when having acceptable levels of mud or other contaminants, a sample ofthe fluid is placed into the sample bottle for later analysis at asurface laboratory. The module is then moved to the next region ofinterest or station.

Fluid flow into the borehole is also routinely produced using dualpacker arrangements, which for example isolate sections of the boreholeduring fluid and pressure testing, essentially in the same manner asdescribed for the MDT tool described above. By reversing the flowdirection dual packer arrangements offer the possibility of conductingfracturing operations which are designed to fracture the formationaround the isolated section of the borehole.

When specifically attempting to inject rather than extract fluid fromthe formation, a testing tool may require modifications such asdescribed for example in the co-owned U.S. Patent Application2006/0000606. The tool described therein is a formation tester for openhole formations incorporating a drill bit to drill through the mudcakewhich accumulates on the wall of the well bore or through zones damagedor contaminated by the drilling process. The tool as described in U.S.2006/0000606 is capable of injecting fluid into the formationsurrounding wellbore for various purposes such as fracturing theformation near the wellbore.

It is further well established to mount logging tools on eitherdedicated conveyance means such as wireline cables or coiled tubing (CT)or, alternatively, on a drill string which carries a drill bit at itslower end. The latter case is known in the industry asmeasurement-while-drilling (MWD) or logging-while-drilling (LWD). In MWDand LWD operations the parameter of interest is measured by instrumentstypically mounted close behind the bit or the bottom-hole assembly(BHA). Both, logging in general and LWD are methods known as such forseveral decades and hence are believed to require no furtherintroduction.

Applications and measurements designed to exploit the flow generated bytools such as the above formation testing tools in combination with NMRtype measurements are described in a number of documents. One example ofthese published documents is the co-owned U.S. Pat. No. 7,180,288 toScheven. Another detailed description of possible NMR-based methods forthe purpose of monitoring flow and formation parameters can be found inthe co-owned U.S. Pat. No. 6,642,715 to Speier et al. and U.S. Pat. No.6,856,132 to Appel et al. A tool which combines a fluidinjection/withdrawal tool with a resistivity imaging tool is describedfor example in the co-owned U.S. Pat. No. 5,335,542 to Ramakrishnan etal. Borehole tools and methods for measuring permeabilities usingsequential injection of water and oil is described in the co-owned U.S.Pat. No. 5,269,180 to Dave and Ramakrishnan and in the co-owned U.S.Pat. No. 7,221,158 to Ramakrishnan. In the co-owned U.S. Pat. No.5,497,321 to Ramakrishnan and Wilkinson, the authors suggest a method tocompute fractional flow curves using resistivity measurements atmultiple radial depths of investigation.

In a paper prepared for presentation at the SPWLA 1st Annual Middle EastRegional Symposium, Apr. 15-19, 2007, Gilles Cassou, XavierPoirier-Coutansais and one of the inventors of the present invention,Raghu Ramamoorthy, demonstrate that the combination of advanced-NMRfluid typing techniques with a dual-packer fluid pumping module cangreatly improve the estimation of the saturation parameter in carbonaterocks. The ability to perform 3D-NMR stations immediately before andafter pump-outs yields both the water and oil saturations (Sw,Sxo)independently of lithology, resistivity, and salinity, in a complexcarbonate environment.

However, the method as demonstrated suffers from a number of limitationswhich makes it difficult to conduct reliable and accurate measurements.Both tools have to be accurately positioned at the same depth atdifferent times. The two 3D-NMR acquisitions must be performed atexactly the same depth as the sampling operation for the manipulation ofthe formation to be reflected in the 3D-NMR measurement. Given that bothtools need to be moved up and down the wellbore to position themcorrectly—and given further that the uncertainty in tool positioning isat least as large as the dimensions of a typical NMR antenna—the testedimplementation as described is not optimal. Moreover, operationalproblems dictate that the tests cannot be performed by the probedirectly because it becomes then more difficult to ensure that the NMRantenna is positioned exactly over the test interval, instead the dualpacker configuration has to be used.

Furthermore, the time to unset the dual packers and move the NMR tooldown to the correct position at the test interval is about 10 minutes. Atypical 3D-NMR measurement may require another 15 minutes of time at thestation. If significant re-invasion occurs during this time, thepost-pumpout 3D-NMR data is affected and can no longer be correlatedwith the flow regime as induced by the tool.

In view of the known art, it is therefore seen as one object of theinvention to improve and enhance known apparatus and methods forcharacterizing formations using induced flow in the formation. It isseen as another object to provide more and better methods of determiningcharacteristic formation and formation fluid properties using measuringapparatus having a volume of investigation overlapping or co-locatedwith the volume in which induced flow occurs.

SUMMARY OF INVENTION

According to a first aspect of the invention, tools and method formeasuring a parameter characteristic of a rock formation are provided,including having in a section of a well penetrating the rock formation adevice for generating a sensing field in a measuring volume within therock formation and a device for causing a flow through the measuringvolume, preferably in the presence of the sensing field, and sensorsresponsive to changes in the sensing field, wherein sensor responses areindicative of the amounts of fluid in the measuring volume in differentstates of the flow, preferably including a state before the generatedflow affects the measuring volume and a state after onset of the flowthrough the measuring volume.

An amount of fluid is defined for the purpose of the invention toinclude parts or percentages of formation fluid which consists ofhydrocarbon and/or parts or the percentage which consists of water. Inthe industry, two of the most utilized of such parameters are oftenreferred to as hydrocarbon saturation (Shc) or oil saturation (So) andwater saturation (Sw), respectively.

In a variant of these embodiments, a fluid is either withdrawn or morepreferably injected into the formation to sweep away the hydrocarbon andobtain a measure of the residual oil saturation (ROS) with thesubsequent measurements. In an alternative variant, a hydrocarbon-basedfluid such as formation crude oil can be injected into the formation toestimate the amount of the residual water saturation (Swr). Bothparameters, ROS and Swr are important end-points in the determination ofthe relative permeabilities relations as a function of saturation andcan thus be ultimately used to determine a measure of the recoveryfactors for the reservoir.

In a further variant of this embodiment, the saturation of a phase inthe formation and flow rates or cuts of fluid phases are measured.Knowledge of the flow volumes or fractional flows in dependence of thesaturation can be used to derive directly the relative permeability of aphase in the formation.

The invention further contemplates the use of a sensing field based onany of the known logging measurement which can sense the change of aparameter within the formation, including sonic, acoustic, magnetic andelectromagnetic sensing fields. Hence the sensors are preferablyresponsive to one of these types of fields and register electro-magneticsignals, resistivity signals, dielectric signals, NMR signals andneutrons capture. In an even more preferred variant, the sensorsregister any such signals at multiple depths as measured in radialdirection from the well. In a preferred embodiment, the sensing fieldcomprises a magnetic field. In a variant of this embodiment,distributions of the spin-lattice relaxation or T1 distributions ordistributions of spin-spin relaxation (T2) are derived from the sensorresponse. However, for the in situ measurements of the time-evolution ofa parameter, faster methods based for example on induction orresistivity arrays may be preferred making hence use of tools such asthe resistivity imaging tool described in U.S. Pat. No. 5,335,542.

In a preferred variant of the NMR based methods, magnetic resonancefluid (MRF) characterization is applied to the sensor response. Magneticresonance fluid (MRF) characterization is a multi-sequence NMRacquisition where polarization time and echo spacing are variedresulting in a sensitivity to diffusion and T1 and T2 distributions. MRFmeasurements can be used to measure both Sw and So in carbonatesindependent of lithology, resistivity and salinity.

The capability to perform and compare two or more MRF measurements in atime-lapse manner before and after an induced flow reduces some of theuncertainties caused by the drilling process and formation invasion.Invasion of drilling fluid filtrate changes the fluid composition nearthe wellbore. Flowing from the formation into the tool has the effect ofreplacing filtrate with formation fluid, thus placing the measuringvolume in the formation into a state much closer to the originalformation. Controlled injection of a known fluid on the other hand canbe used advantageously to create a zone which is more completely flushedthan by merely the uncontrolled and unmonitored invasion of mudfiltrate.

While it is possible to generate flow by any tool which is capable ofcausing a pressure gradient across the surface of the well, the presentinvention employs preferably tools and method which are coupled withmeans to determine flow related parameters. Preferred tools aretherefore variants of the known formation sampling tools modified suchthat the sensing tool can project its sensing field into the volume ofthe formation subject to the flow caused by the sampling tool.

Typically the flow is caused by engaging the wall of the well with aprobe of the sampling tool and using a pumping mechanism to withdrawfluid from the formation. However, in a further embodiment of theinvention the flow can be alternatively or alternatingly caused byinjecting a fluid into the formation. In this embodiment of theinvention, the parameter can be measured while having a flow into andout of the formation.

In another aspect of the invention, the monitored amounts of fluids inthe formation can be analyzed for compositional changes in thehydrocarbon phase as caused by the flow. Again, it is a preferredembodiment of this aspect of the invention to repeat stationarymeasurements under different flow conditions, i.e. before, during andafter the induced flow.

In a preferred embodiment of this aspect of the invention, the amount ortotal volume of hydrocarbon in a measuring volume within the formationis decomposed in accordance with the values of a parameter which can bederived from the measurement. It can be observed that these fractionedor decomposed parts of the hydrocarbon behave differently underdifferent flow conditions. Such measurements can therefore lead toparameters related to the composition of the formation fluid. In avariant of this embodiment, this parameter is the T1 or T2 distributionor a parameter derivable from these distributions, such as viscosity.Observing the reservoir fluid decomposed according to such a parameterallows for better estimates of recoverable reserves and/or theeffectiveness of enhanced oil recovery (EOR) treatments.

In accordance with a further aspect of the invention, the method can beused to determine the effectiveness of enhanced oil recovery in variousmanners. Enhanced oil recovery (EOR) methods include the injection ofspecialized chemical compounds such as surfactants or water blockinggels into the formation. EOR methods also include thermal-basedreservoir treatments such as steam or gas injections. By monitoring thereaction of the fluid in the measuring volume within the formation, itis possible to estimate the efficacy of such an EOR treatment on alarger reservoir scale. In an embodiment of this aspect of theinvention, the effectiveness of chemicals, such as surfactants, wheninjected into the formation can be monitored in situ and evaluatedaccordingly to derive further important parameters such as effectivehydrocarbon recovery factors with and without the treatment.

Further details, examples and aspects of the invention will be describedbelow referring to the drawings listed in the following.

BRIEF DESCRIPTION OF THE FIGURES

FIG. 1A illustrates a conventional drilling operation;

FIG. 1B illustrates a logging operation in accordance with an example ofthe present invention;

FIGS. 2A and 2B show a schematic frontal and a cross-sectional view of atool for use in the present invention;

FIG. 3 shows a schematic cross-sectional view of another tool for use inthe present invention;

FIG. 4A illustrates a typical measurement as performed by an NMR tool;

FIGS. 5A and 5B illustrates interpretations enabled by the presentinvention; and

FIG. 4B shows another possible measurement based on the presentinvention.

DETAILED DESCRIPTION

In FIG. 1A, a well 11 is shown in the process of being drilled through aformation 10. A drill string 12 is suspended from the surface by meansof a drilling rig 13. A drill bit 12-1 is attached to the bottom of thedrill string 12.

While drilling, a drilling fluid is circulated through the drill string12 and the drill bit 12-1 to return to the surface via the annulusbetween the wall of the well 11 and the drill string 12. During thisprocess, part of the drilling fluid invades a shallow zone 15 around theborehole 11 thus contaminating the formation fluid.

After completing the drilling through a hydrocarbon bearing formation, awireline tool 16 as shown in FIG. 1B is lowered into the well 11 using awireline cable 17. In the example as illustrated, the wireline toolincludes a formation testing device 16-1 to be used for generating aflow in the formation and an NMR-based tool 16-2 with a combination ofpermanent magnets and antennas (not shown) to generate a magnetic fieldwithin the volume of the formation affected by the flow. Such tools havebeen described in the prior art, including the co-owned U.S. Pat. No.7,180,288 to Scheven, the co-owned U.S. Pat. No. 6,642,715 to Speier etal., and the U.S. Pat. No. 6,856,132 to Appel et al.

A further variant of such a tool is illustrated in FIGS. 2A and 2Bshowing a frontal and cross-sectional view, respectively, of theschematics of a combined sampling and NMR tool.

The body 20 of the downhole logging tool includes a sampling probetaking the shape of a pad 21. The pad 21 includes an outer zone 211 ofmagnetic material behind a sealing layer of elastic material. Themagnetic material of this example is permanently magnetic and can hencegenerate a magnetic field in those parts of the formation which face theprobe. An inner zone of the pad 21 includes an antenna area 212 and theflowline 213. A feed circuit 22 to power and control the antenna islocated behind the pad 21. The flowline includes a flowmeter Q similarto the known devices.

The antenna is designed to deliver NMR pulses 23 into the formation. Thetool as illustrated is in a state of injecting fluid from the tool body20 into the formation 10. In other states, fluid may flow in reversedirection, i.e., from the formation 10 into the flowline 213. The toolshown is distinguishable from known designs of combined sampling and NMRtools by having the antenna 212 in a recessed area of the pad 21. It isseen as a novel aspect of such designs to have the recessed area acteffectively like a funnel, thus drawing in or injecting flow from abigger effective area and in turn enlarging the measuring volume whereflow and magnetic field overlap. The recessed area serves further toprotect the antenna from the impact and sealing forces acting when thepad makes contact with the formation.

For an electromagnetic or resistivity-based measurement, the combinationof an NMR tool and formation testing tool as shown above can be replacedby a combination of resistivity array tool and formation testing tool.Such a tool is described for example in the co-owned U.S. Pat. No.5,335,542 to Ramakrishnan et al. Other sensing fields require acorresponding change of the type of source and receivers in the toolbody. However for most of the known sensing fields whether acoustic,sonic or electromagnetic, corresponding logging tool designs exists andcan be thus adapted to methods and tools described herein.

Integrated into the flowline of the sampling tool are typically furthermeasuring devices (not shown), such as optical, NMR, or resistivitybased sensors etc., to measure composition-related parameters of thesampled or ejected flow inside the tool. These devices include alsoflowmeters Q to determine the total flow Qw+Qo and the water flow Qw andthe hydrocarbon flow Qo. The flowline 213 is further connected to a flowgenerator or pump (not shown) located within the body of the loggingtool. The flow generator is designed to move fluids from the formationinto the body of the tool or from a storage tank (not shown) within thebody of the tool into the formation.

A wireline suspended dual packer tool suitable for performingmeasurements in accordance with another example of the invention isshown in FIG. 3. The tool 31 of FIG. 3 is suspended from a wireline 32into an open hole. It has a pair of packers 33 with integrated arrays ofsensors 34. The sensors can be designed as an array of electrodes,antennas gamma-ray receivers or emitters etc. depending on themeasurement to be performed. The pair of packers isolates a zone 30 ofthe formation. The tool further comprises a fluid reservoir chamber 35connected to the fluid ports 361 via a flow line 36. The flow throughthe flow line 35 is driven by a pumping module 37. The pumping modulecan be designed to support flow from the formation into the reservoirchamber or from the chamber into the formation. Depending on the type ofexperiment to be performed, the chamber may contain sample fluids suchas water or oil, or solutions of active chemicals to modify theformation, the formation fluids, or the response of the formation orformation fluid to the sensing field. The lines 38 and 39 provide anelectrical connection and a hydraulic connection, respectively, to thepacker 33 and the sensors 34.

It is important to note that the measurement as proposed in the presentinvention will result in a response signal from the fluid as locatedinside the measuring volume and hence inside the formation. Previousefforts of combining NMR and a sampling tool have mostly focused onmeasuring the properties of the sampled fluid or its velocity after itleaves the formation and moves through the flow line of the tool. In thepresent invention, the sampling tool is employed as a means to generatea flow in the formation. This flow changes the values of parametersassociated with the formation whilst leaving others unchanged. It hasbeen observed that by recording such changes, parameters of greatimportance for the characterization of the formation can be determinedwith potentially much higher accuracy, revealing even previously unknownaspects.

In a first example of an embodiment of the invention, the oil and watersaturations of the formation fluids are determined as a function of theflow rate. The saturations can be determined for example by evaluatingmeasured T1 or T2 distribution curves. To illustrate the principle ofthe evaluation, a simplified example of such curves is shown in FIG. 4A.The water signal is shown as a solid line 41 and oil as a dashed line42. Saturations can be determined from such a measurement by calculatingthe ratio of the relative areas under the curves to the total area.

The response of the formation to many measurements, including the NMRtype measurement above, can be modified through injection of a suitablechemical. Using for example either MnCl2 or NiCl as part of any injectedfluid reduces the water response signal or, at the very least, shifts itto very short T2 values. This effect results in a clear separationbetween the water and oil signals in the T2 domain and the residual oilsaturation estimation becomes a simple volumetric determination based onthe measured T2 distribution.

Whilst the example as illustrated is simplified in order to makeimportant aspects more transparent, it is expected that realmeasurements are based on more advanced methods of evaluating NMR datasuch as MRF methods or other any known method to acquire and interpretthree dimensional (3D) NMR data. For details of the theory andimplementation of the MRF method, reference can be made to Freedman, R.,Sezginer, A., Flaum, M., Matteson, A., Lo, S., and Hirasaki, G. J.: “ANew NMR Method of Fluid Characterization in Reservoir Rocks:Experimental Confirmation and Simulation Results,” SPE 63214,Transactions of the 2000 SPE Annual Technical Conference and Exhibition,Dallas, Tex., USA, 1-4 Oct. 2000.

With the saturation values determined using either the NMR based methodsas described in the above example or measurements based on other sensingfields, the flowmeter Q can be used to measure the water cut or flow Qwand/or the hydrocarbon cut or flow Qo of the sampling tool. The term“cut” is used to indicated the amount of a single phase in what istypically a multiphase flow produced from the borehole.

If required, the time lag between the flow measurements and thesaturation measurements can be compensated for by for examplecalculating the average flow velocity between the location of thesaturation measurement and the flowmeter location inside the tool body.Another way of performing such compensation may include usingcorrelations between the NMR measurements and the flowmeter andselecting the time lag which maximizes such correlations. Thecompensation ensures that the measurement as performed by the flowmeterreflects the composition of the flow as it passes through the measuringvolume of the NMR tool for evaluation.

In a preferred embodiment of the invention the measured saturations andflow rates are matched to fit a relations or model which includes therelative permeabilities k(ro) or k(rw). In principle all measured pointslie on curves such as shown in FIG. 5A.

In FIG. 5A, there are shown the relative permeability kro of hydrocarbonas a function of saturation and the relative permeability krw of wateras a function of saturation. The endpoints of both curves are defined bythe residual water saturation Swr and the residual hydrocarbonsaturation ROS. Based on the current knowledge of the theory of thisrelation, it is in many cases not required to determine more than twopoints to derive a useful estimate of a relative permeability curve.These two points could be the permeability at the residual watersaturation Swr and the residual hydrocarbon saturation ROS. However theaccuracy of such an estimate or model is increased by determining moremeasurements points on the curves. A further, more detailed example of amodel based approach for evaluating saturation measurements to deriverelative permeabilities is described in: “Water-cut and fractional-flowlogs from array-induction measurements” by T. S. Ramakrishnan and D. J.Wilkinson, 1999 SPE Reservoir Evaluation and Engineering 2 (1), pp.85-94.

Once the relative permeabilities krw(Sw) and kro(Sw) are established asfunctions of the saturation, it is possible to derive the fractionalflow using for example equation [1] below with μw being the μw and

fw(Sw)=(krw(Sw)/μw)/(krw(Sw)/μw+kro(Sw)/μo)   [1]

resulting in curves for the fractional flowrates as a function of thesaturation as shown for the flowrate fw(Sw) of the water phase in FIG.4B. Once established, this function can be used to determine importantparameters. For example, a measure of the recoverable oil in theformation can be derived by measuring the actual saturations and theirrespective distance to the endpoints of the saturation curves indicatingthe residual oil or water saturations.

In another example of the invention, the T1 or T2 distributions as shownin FIG. 4A can be recorded as a function of time and hence as a functionof the flow which passed through the monitored formation volume. Thebenefit of such a measurement can be demonstrated by comparing theschematic FIGS. 4A and 4B. The latter figure shows the same measuringvolume but after an injection of water.

The measured distribution gives an indication of the residual oilsaturation ROS by evaluating the area of the “oil peak”, which isreduced after the injection of water from the tool as described above.However apart from the determination of saturations, the distributioncan further be evaluated to make determinations as to the composition ofthe hydrocarbon.

It is generally known that the absolute value of T1 or T2 can be linkedto fluid related parameters such as viscosity. Hence each value of T1(or T2) is taken in this example as a value representative of viscosity.

In FIGS. 4A and 4B, which together illustrates the case of a compositionchange in the formation fluid due to a water injection, the oil peak isnot only reduced in amplitude, but the amplitude reduction in FIG. 4Brelative to the original amplitudes of FIG. 4A differs for differentvalues of T1. In the illustrated example, the composition of theformation oil has changed, with the low viscosity fractions of the oil(at higher T1 values) being apparently flushed more effectively from theformation than the higher viscosity fractions. The higher viscosityportion of the formation oil remains in place and forms a relativelylarger fraction of the residual oil which cannot be produced by waterinjection or flush alone.

To observe compositional changes such as described in the example aboveprovides important information to assist in decisions concerning themethods chosen at various stages in the life of the reservoir to recoverits hydrocarbon content. It can also be used in determining the mostefficient form of EOR treatment. If, for example, the recoverable oilleft in the formation is more viscous than the produced oil, EORtreatments will need to be planned differently taking into account thechange in the viscosity of the remaining oil.

Apart from drawing conclusions on the efficacy of types of EORtreatments, it is further possible to measure the effects of such atreatment on a very small scale but within a very short time period.Repeating the injection measurements as described above with an EORtreatment fluid rather than water, it is possible to monitor directlythe changes in the formation, in particular the residual oil saturationwithout and with the EOR treatment tested. When testing a chemical basedmethod, the relevant chemical components can be mixed to the internalfluid flow inside the tool. If a heat treatment is contemplated fortesting, the fluid injected can be heated inside the tool body prior toinjection into the formation. Thus the invention can provide a very fastscreening method for a wide variety of existing and future EORtreatments which would otherwise take months or even years to test.

1. A tool for characterizing a subterranean formation, the toolincluding a sensing device for generating a sensing field within ameasuring volume of the formation; a flow generating device for causinga flow through the measuring volume; and sensors responsive to changesin the sensing field, wherein sensor responses are indicative of anamount of constituent fluid phases in the measuring volume under atleast two different flow conditions in the formation.
 2. The tool ofclaim 1 wherein the at least two different flow conditions include atleast one of the condition before the flow generating device caused theflow and the condition after the flow generating device caused the flow.3. The tool of claim 1 wherein the flow generating device is designed togenerate the flow in the presence of the sensing field.
 4. The tool ofclaim 1 wherein the at least two different flow conditions comprise thecondition of a flow being present at a time of registering the sensorresponses.
 5. The tool of claim 1 wherein the sensor response areindicative of saturations of water and/or hydrocarbon phases.
 6. Thetool of claim 1 designed to determine at least one of residual oilsaturation (ROS) or residual water saturation (Swr).
 7. The tool ofclaim 1 having a flow generator to inject fluids into the formation. 8.The tool of claim 1 having a flow generator to inject fluids into andwithdraw fluids from the formation.
 9. The tool of claim 1 furthercomprising a flowmeter to determine flow rates of fluids passing throughthe tool.
 10. The tool of claim 1 having a flowmeter to determine flowrates of at least one of water or hydrocarbon flow passing through thetool.
 11. The tool of claim 7 wherein the injected fluid is an EnhancedOil Recovery (EOR) fluid designed to change the recovery rate ofhydrocarbons from the formation.
 12. The tool of claim 1 having asealing pad extendible from a main body for establishing a sealingcontact with the formation, wherein the sealing pad comprises an antennaelement in a central recessed area forming a gap volume between theantenna element and the formation as the sealing contact is established.13. A method of characterizing a subterranean formation including thesteps of having in a section of a well penetrating the rock formation asensing device for generating a sensing field within a measuring volumeof the rock formation; a flow generating device for causing a flowthrough the measuring volume, and sensors responsive to changes in thesensing field, wherein sensor responses are indicative of an amount ofconstituent fluid phases in the measuring volume under at least twodifferent flow conditions in the formation.
 14. The method of claim 13wherein the at least two different flow conditions include at least oneof the condition before the flow generating device caused the flow andthe condition after the flow generating device caused the flow.
 15. Themethod of claim 13 comprising the step of generating the flow in thepresence of the sensing field.
 16. The method of claim 13 wherein the atleast two different flow conditions comprises the condition of a flowbeing present at a time of registering the sensor responses.
 17. Themethod of claim 13 comprising determining saturations of water and/orhydrocarbon phases.
 18. The method of claim 13 comprising the step ofdetermining at least one of residual oil saturation (ROS) or residualwater saturation (Swr).
 19. The method of claim 13 comprising the stepof injecting fluids into the formation.
 20. The method of claim 19,wherein the injected fluid is an Enhanced Oil Recovery (EOR) fluiddesigned to change the recovery rate of hydrocarbons from the formation.21. The method of claim 13 comprising the step of injecting fluids intoand withdrawing fluids from the formation.
 22. The method of claim 13further comprising the step of measuring in the wellbore flow rates offluids representative of fluid passing through the formation.
 23. Themethod of claim 13 further comprising the step of measuring in thewellbore flow rates of at least one of water or hydrocarbon phase offluids representative of fluids passing through the formation.
 24. Themethod of claim 13 comprising the step of determining parametersindicative of a fractional flow state and saturations in the volumebeing in the fractional flow state.
 25. The method of claim 13comprising the step of fractioning the amount of constituent fluidaccording to a parameter indicative of the composition of theconstituent fluid and determining shifts in the fractioning betweendifferent flow conditions.